Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in Canada and Venezuela. Oil sands are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as “bitumen,” but which may also be called heavy oil or tar.
The crude bitumen contained in the Canadian oil sands is described as existing in the semi-solid or solid phase in natural deposits. Bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. The viscosity of bitumen in a native reservoir is high. Often times, it can be in excess of 1,000,000 cP. Regardless of the actual viscosity, bitumen in a reservoir does not flow without being stimulated by methods such as the addition of solvent and/or heat. At room temperature, it is much like cold molasses.
Due to their high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow in order to produce and transport them. One common way to heat bitumen is by injecting steam into the reservoir. The quality of the injected fluid is very important to transferring heat to the reservoir to allow bitumen to be mobilized. Quality in this case is defined as percentage of the injected fluid in the gas phase. The target fluid quality is near 100% vapor, however, injected fluid in parts of the well can have a quality below 50 percent (more than 50% liquid) due to heat loss along the wellbore. Thus, in many steam injection techniques, the quality of steam drops off farther from the injection point, resulting in uneven heating. This is illustrated in FIG. 3, showing a typical SAGD process with uneven steam chamber shown in black.
Steam Assisted Gravity Drainage (SAGD) is the most extensively used technique for in situ recovery of bitumen resources in the McMurray Formation in the Alberta Oil Sands (Butler, 1991) and other reservoirs containing viscous hydrocarbons. In a typical SAGD process, two horizontal wells are vertically spaced by 4 to less than 10 meters. The production well is located near the bottom of the pay and the steam injection well is located directly above and parallel to the production well. In SAGD, steam is injected continuously into the injection well, where it rises in the reservoir and forms a steam chamber.
With continuous steam injection, the steam chamber will continue to grow upward and laterally into the surrounding formation. At the interface between the steam chamber and cold oil, steam condenses and heat is transferred to the surrounding oil. This heated oil becomes mobile and drains, together with the condensed water from the steam, into the production well due to gravity segregation within the steam vapor and heated bitumen and steam condensate chamber.
This use of gravity gives SAGD an advantage over conventional steam injection methods. SAGD employs gravity as the driving force and the heated oil remains warm and movable when flowing toward the production well. In contrast, conventional steam injection displaces oil to a cold area where its viscosity increases and the oil mobility is again reduced.
However, gravity is not the only important factor for SAGD. Many studies have shown that the performance and ultimate success of SAGD depends on many factors including reservoir properties, steam chamber development, the length, spacing and location of the two horizontal wells, heat transfer, heat loss, and the ability to impact steam trap control to prevent inefficient production of live steam.
Typically, SAGD wells are drilled about 5 meters apart vertically to achieve steam trap control whereby a gas-liquid (steam-vapor) interface is maintained above the production well to prevent short-circuiting of steam and undue stress on the production well sand exclusion media. In order to establish initial communication between the wells, a startup period where steam is circulated for 3 to 5 months in each well (both production and injection wells) prior to starting SAGD operation is necessary for a successful SAGD recovery. However, this 3 to 5 month startup time increases the overall cost of SAGD because of the amount of steam required and the delay before oil production can begin. Decision makers may limit projects available for SAGD production because of this added cost.
Well characteristics and design are also important to SAGD performance. The standard SAGD well design employs 800 to 1000 meter slotted liners with tubing strings attached near the toe and near the heel in both the injection and the production wells to provide two points of flow distribution control in each well, as illustrated in FIG. 1. However, in the typical SAGD operation, steam heating is uneven, falling off away from the injection point and reducing effectiveness and increasing costs.
As such, there is a need to develop more thermally efficient production techniques while increasing the economic viability of the SAGD process. Conventional reservoir completion practice, with a toe string, limits the minimum liner diameter for a given flow capacity. Thus, a method that reduces material, reduces steam use, reduces the number and size of tubing strings, and reduces startup time while improving SAGD performance is needed.